Steam quality boosting

ABSTRACT

Disclosed are methods for providing steam suitable for injecting into a subterranean oil well, wherein fuel is combusted within a conduit that contains the steam to provide direct heat transfer of the heat of combustion to the steam.

FIELD OF THE INVENTION

The present invention relates to improvements in the production of streams containing steam, especially steam-containing streams useful in enhancing the production of oil from an oil producing well.

BACKGROUND OF THE INVENTION

Steam can be used to enhance the recovery and production of oil from subterranean formations containing the oil. Steam is injected into a well to heat the oil in the formation, thereby reducing the viscosity of the oil and making recovery of the oil possible from the same well or more often from another well. In some situations the injection of steam makes it possible to recover oil that could not otherwise be recovered at all, and in other situations the injection of steam makes it possible to recover more oil than would otherwise be possible.

The steam used for this purpose is generated in a suitable apparatus, such as a “once through steam generator” (OTSG) which produces steam at less than 100% quality. 80% quality steam is typical. Water is then separated from the steam. The saturated steam is then sent through insulated piping to a wellhead for injection into a well. In some cases the wellhead may be many miles away. As the steam travels through the piping, the steam loses some heat in spite of the insulation, which leads to some of the steam condensing and therefore reducing the thermal energy available for delivery to the formation.

Steam quality generated in conventional SAGD boilers is limited to 80% due to water quality constraints. Conventional practice to increase the energy delivered to the reservoir, with the ultimate goal to increase the oil production, requires additional boilers to increase the steam throughput. However, this solution is unattractive as it is highly capital intensive.

BRIEF SUMMARY OF THE INVENTION

The present invention provides methods to protect or boost the temperature and/or quality of the steam that is used for downhole injection in an oil well.

One such method is a method of providing steam suitable for injection into a subterranean oil well, comprising

combusting fuel with gaseous oxidant and subjecting a stream that comprises steam flowing from a source of said steam to a subterranean oil well to direct heat transfer to said stream of heat produced by said combustion. Preferably, the steam quality of said stream is thereby increased to a value that is above 80% and that is higher than the steam quality of the stream.

In a preferred embodiment of the methods, liquid water is separated from the stream (i.e. physically) before or after the direct heat transfer.

In another preferred embodiment of the invention, the stream that is produced can be further heated to superheat the steam and/or to increase the steam quality of the stream.

Another aspect of the present invention is a method of providing steam suitable for injection into a subterranean oil well, comprising

feeding fuel and gaseous oxidant into a stream that comprises steam flowing in a conduit from a source of said steam in a subterranean oil well, wherein said fuel and said oxidant are fed into said stream from one or more outlets located in said stream within said conduit, and

combusting said fuel with said oxidant at one or more of said outlets in direct contact with said steam, and heating said steam by direct contact of said steam with hot combustion products produced by said combustion.

As used herein, the “steam quality” of a stream means the amount of steam present in the stream as a percentage of all water present in the stream regardless of what phase the water is in.

As used herein, “superheated steam” means steam which is at a temperature that is higher than its vaporization (boiling) point at the absolute pressure where the temperature measurement is taken. Superheated steam does not contain liquid water.

As used herein, “direct heat exchange” and “direct heat transfer” mean transfer of heat to a material, which is intended to be heated, by directly contacting it with another material from which heat is transferred.

As used herein, “indirect heat exchange” and “indirect heat transfer” mean transfer of heat to a material, which is intended to be heated, from another material from which heat is transferred, in which the material to be heated does not directly contact the material from which heat is transferred.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a flowsheet of a system depicting an embodiment of the present invention for use in the recovery of oil from oil wells.

FIG. 2 is a cross-sectional view of a stream depicting an embodiment of one aspect of the invention.

FIG. 3 is a cross-sectional view of a stream depicting another embodiment of one aspect of the invention.

FIG. 4 is a flowsheet of a system depicting another embodiment of the present invention for use in the recovery of oil from oil wells.

FIG. 5 is a cross-sectional view of a typical embodiment of apparatus useful in the present invention.

FIG. 6 is a cross-sectional view of another embodiment of apparatus useful in the present invention.

FIG. 7 is a cross-sectional view of an oil well showing an embodiment of the present invention in which the steam is being heated within the well.

FIG. 8 is a top view of one possible embodiment of the embodiment shown in FIG. 5.

DETAILED DESCRIPTION OF THE INVENTION

Referring to FIG. 1, one embodiment of a SAGD steam system is shown. The SAGD steam system comprises a once through steam generator (OTSG) which includes a conventional boiler 10 which is fired by combustion of fuel 101 and oxidant 102 streams. The fuel 101 can be any hydrocarbon fuel, such as natural gas. Oxidant 102 is gaseous and can be air, or a stream having an oxygen content greater than 21 vol. % such as oxygen-enriched air or commercially provided oxygen having an oxygen content of 90 vol. % or higher. Boiler 10 may be of a design that includes long sections of straight tubing bounded by one or more removable end sections.

The boiler 10 typically produces stream 104 with a steam quality ranging from 75-85%. The temperature of stream 104 will typically be 450° F. to 600° F. and the pressure of stream 104 will typically be 500 psia to 1500 psia. The relatively low steam quality is imposed by utilization of low quality boiler feed water 204 as the source of the water 209 that is fed to boiler 10 to be heated to produce the steam in stream 104, and the necessity of conditioning to prevent contaminants in the water (such as CaCO₃, silica, MgCO₃ and the like) from solidifying or precipitating on the boiler's heat transfer area. A removable end section of the boiler allows insertion of mechanical devices to scrape the deposits off of the surface of the tubes or other heat transfer surfaces.

In the embodiment of FIG. 1, feed stream 104 comprising steam and liquid water is fed to system 11 for vaporizing liquid water present in feed stream 104. System 11 combusts hydrocarbon fuel (such as natural gas) and a gaseous oxidant stream which can be air but more preferably has an oxygen content higher than 21 vol. % such as pure oxygen or oxygen enriched air. Stream 301 represents one of fuel or oxidant, and stream 302 represents the other of fuel or oxidant, as described herein with respect to FIG. 2. The system 11 heats the wet steam primarily by direct heat exchange with the heat of combustion of the fuel and oxidant to vaporize at least a portion, or all, of the liquid water present in stream 104, so that the steam quality of stream 106 that enters the separator 20 has been increased and is higher than 80%, preferably 90% to 98%, and more preferably in the range 92-97% while keeping the non-condensable (CO₂, N₂) content in the stream 106 below 1-2%. The pressure in the portion of system 11 in which the combustion and direct heat exchange occur will typically be 500 psia to 1500 psia. The temperature of stream 106 will typically be 450° F. to 600° F. and the pressure of stream 106 will typically be 500 psia to 1500 psia.

FIG. 2 depicts one embodiment of system 11. Stream 104, downstream from boiler 10, is flowing in a conduit 100 or equivalent conveyance. Conduit 100 is made of any material capable of carrying steam at temperatures and pressures suitable for oil recovery operations. Such materials are known in this field, and are currently used in operations that employ steam to enhance oil recovery.

The embodiment of system 11 that is shown in FIG. 2 includes burner 310 which extends into conduit 100. The end 311 of burner 310 inside conduit 100 includes outlets 304 and 306 which are shown as concentric, with outlet 306 surrounding outlet 304. However, outlets 304 and 306 may instead be side-by-side as they pass through conduit 100. Outlet 304 is connected to feed line 301 through which is fed one of either oxidant or fuel, preferably fuel. Outlet 306 is connected to feed line 302 through which is fed the other of either oxidant or fuel, preferably oxidant. The axis of burner 310 can be oblique relative to the flow of the steam, as shown in FIG. 2, or can be relatively parallel to the stream as shown in FIG. 6.

Oxidant and fuel are combusted in flame 311 within conduit 100, in direct heat exchange contact with the stream 104. The combustion generates heat which is used as described herein.

It should be noted that in the apparatus depicted in FIG. 2, there is no enclosure forming a combustion chamber within which the fuel and the oxidant combust before their combustion products contact the stream 104 in the conduit. Instead, as noted herein, the flame directly contacts the steam. The hot combustion products formed by the combustion also directly contact the stream 104 in conduit 100. Stream 104 is thus heated by direct heat exchange with the heat of combustion.

FIG. 3 depicts another embodiment of system 11. Referring to FIG. 3, stream 104 is flowing in conduit 100 or equivalent conveyance, as described above. Gaseous oxidant and fuel are fed into chamber 308. As in FIG. 2, feed line 301 represents one of the gaseous oxidant and fuel, and feed line 302 represents the other of the gaseous oxidant and fuel. The gaseous oxidant and fuel are combusted within chamber 308 to form flame 311 (including hot combustion products) in chamber 308 which extend from inside chamber 308 to outside chamber 308. The flame and hot combustion products directly contact stream 104 which is thus heated by direct heat exchange. Preferably, the heat exchange from chamber 308 is assisted by feeding an auxiliary stream gas such as air, nitrogen, argon, carbon dioxide, steam, or mixtures of any of these, into chamber 308 wherein the auxiliary gas is heated by the combustion in chamber 308 and flows out of chamber 308 into stream 104 to assist in the direct heat exchange to stream 104. The auxiliary stream is shown as 323. A stream of steam 324 can be fed as shown into stream 323 from outside conduit 100, or can be aspirated into chamber 308 from stream 104 within conduit 100.

In operation of system 11, fuel and oxidant are fed through their respective feed lines from conventional sources thereof, such as storage tanks with suitable valves and controls. Preferred fuels include gaseous hydrocarbons such as natural gas, propane, methane, mixtures thereof, and the like. Preferred oxidants include air, oxygen-enriched air having an oxygen content greater than 21 vol. %, and oxygen streams containing at least 90 vol. % or at least 95 vol. % or even at least 98 vol. % oxygen. The fuel and oxidant are fed to burner 310 and combusted at the respective outlets 304 and 306, or fed to chamber 308 and combusted as described above. The flow rates of the fuel and oxidant to system 11 will depend on the size of the apparatus, the size of the conduit 100, the flow rate of the stream 104, and the amount of combustion energy that one desires to create. The stoichiometric ratio between the fuel and oxidant that are fed to system 11 should be such that there is no more than 5% excess oxygen. Preferably the stoichiometric ratio should be 1:1 or with an excess of fuel.

Steam generated from the combustion of the fuel and oxidant in system 11 can increase the amount of steam delivered to the well (compared to what was produced in boiler 10). Other components of the combustion reaction products (particularly CO₂) may be advantageous for oil recovery or at worst, inert.

The combustion in system 11 forms steam-boosted stream 106 which exits system 11 and is fed to separator section 20 which comprises one or more vessels, such as flash drum separators, in which the steam (vapor) and liquid components of stream 106 are separated from each other. The steam component leaves separator section 20 as saturated steam stream 105 having a steam quality of at least 99%. The liquid component of stream 106 leaves separator section 20 as liquid, also known as “blowdown”, stream 207. The temperature of stream 105 will typically be 450° F. to 600° F. and the pressure of stream 105 will typically be 500 psia to 1500 psia.

Stream 105 can optionally but preferably be fed to one or more optional steam superheating systems wherein the temperature of the saturated steam leaving the separator 20 is heated to a higher temperature that is not so high that it will damage the steam pipeline and well bore materials, but is still above the saturation temperature of the steam in stream 105. This treatment helps overcome heat losses on the steam's path from separator section 20 to the oil well or wells designated as 40. This heat transfer can be by direct or indirect heat transfer.

One embodiment of an optional steam superheating system is shown in FIG. 1 as system 12 which includes a heater 13 that is fired by combustion of a fuel 401, such as natural gas, and gaseous oxidant 402 which may be air or a stream having an oxygen content higher than 21 vol. %. The oxidant 402 can be fed at low pressures which will typically be 14.8 psia to 15.5 psia. Preheater 14 is also preferably employed to preheat the combustion oxidant 402 by indirect heat transfer from stream 403 of the hot gaseous products of combustion (flue gases) produced in heater 13. In system 12, stream 105 is heated by indirect heat exchange. With indirect heat transfer, the stream 105 can be flowed through tubes in heater 13 whose exteriors are exposed to hot products of combustion of fuel 401 and oxidant 402, and heat flows from the hot combustion products through the tubes into stream 105. Alternatively, the products of combustion of fuel 401 and oxidant 402 can be flowed through tubes in heater 13 whose exteriors are exposed to stream 105, and heat flows from the combustion products through the tubes into stream 105 by indirect heat exchange. Where stream 105 contains little or no liquid water (no more than 2 wt. % liquid), stream 107 leaves heater 13 as superheated steam.

FIG. 4 depicts an alternative embodiment of the invention, in which stream 105 which leaves separator 20 is fed to a system 15, which can be constructed and operated as described above with respect to system 11, and which heats the steam in stream 105 by direct heat exchange. Where stream 105 contains little or no liquid water (no more than 2 wt. % liquid), stream 107 leaves system 15 as superheated steam.

In those embodiments of FIG. 1 and FIG. 4 in which stream 105 contains liquid water, stream 107 will have a steam quality higher than that of stream 105, and enough energy may be imparted to stream 107 so that stream 107 contains no liquid water and constitutes superheated steam.

Before being sent to the oil reservoir through the pipeline system 30 to be injected in the oil well or wells 40, stream 107 will preferably have a steam quality of at least 98%, and the steam in stream 107 will typically be superheated by 10° F. to 200° F. The temperature of stream 107 will typically be 500° F. to 750° F. and the pressure of stream 107 will typically be 500 psia to 1500 psia. The duty performed by system 13 or system 15 will be defined by its location relative to separator section 20 and well(s) 40, and by the proportion of steam in stream 107 that undergoes condensation due to loss of heat from pipeline system 30.

As described more below, one or more systems 13 and/or one or more systems 15, and one or more systems as described herein relative to FIGS. 5, 6, 7 and 8, can be located at any locations along the piping 30 to the oil wells and/or on individual pipes leading individual ones of the oil wells 40.

The steam injected into the oil formation in the wells condenses and the heat released to the reservoir upon condensation reduces the heavy oil viscosity and density, forming an oil/water emulsion 201, which returns to the surface. The emulsion 201 is separated in separation train 50. This separation produces oil 202 that can be used or subjected to further processing at the site or elsewhere. This separation also produces water stream 203 which is sent to water treatment section 60 for further purification. Makeup water 210 should be provided into the overall process, to make up for water losses into the oil well formation and/or to evaporation. A preferred location to feed makeup water is prior to water treatment section 60. In FIG. 1, stream 210 denotes a stream of makeup water.

Typically, the liquid blowdown 207 from the separator 20 is cooled to recover its heat content in a heat exchanger 80, and then sent to a condensate recovery section 70, where part of the blowdown stream 207 may be partially evaporated, so that the waste water discharge stream 205 represents only up to 5% of the total boiler feedwater stream 208. Other condensate recovery/treatment options are available. The condensate from the partial evaporation step, the treated portion 206 of the blowdown is mixed with the treated water 204 from the water treatment section 60, to form stream 208 which is preheated in the heat exchanger 80 by indirect heat exchange from the blowdown stream 207. The resulting preheated stream 208 is further preheated in economizer 90 by indirect heat exchange with the flue gases 103 leaving the OTSG boiler 10, to produce feed stream 209 which is fed to boiler 10.

In additional description of the invention, referring now to FIGS. 5-8, burner 310 is situated inside conduit 100. In one embodiment, burner 310 is located at a bend or elbow in conduit 100, so that burner 310 extends through a wall of conduit 100. This embodiment is shown in FIG. 5. In other embodiments, burner 310 is located in a straight section of conduit 100, as shown in FIGS. 6 and 7. In the embodiment of FIG. 6, typical of an above-ground installation, burner 310 can be secured to the inner surface of conduit 100 by suitable brackets 321 (whether conduit 100 is oriented vertically, horizontally, or otherwise), and feed lines 301 and 302 pass through the wall of conduit 100.

In the embodiment of FIG. 7, typical of a subterranean installation in which oil well 731 extends from the surface 730 of the earth to formation 732 which contains oil 733 that is recovered at the surface, conduit 100 extends within oil well 731 to the formation 732. Burner 310 can be suspended within conduit 100 from feed lines 301 and 302 that extend from the surface 730, or by auxiliary support cables (not shown). Steam 108 (which may have been treated in the manner described herein with respect to FIGS. 1-4) is fed down conduit 100 toward burner 310, at which fuel and oxidant which are fed from the surface combust and impart energy to steam 108 which then enters the formation 732. In this embodiment, burner 310 can be located in the oil formation or anywhere below the surface 730.

In FIGS. 5-7, the end of burner 310 inside conduit 100 includes outlets 304 and 306 which are shown as concentric, with outlet 306 surrounding outlet 304. However, outlets 304 and 306 may instead be side-by-side. Outlet 304 is connected to feed line 301 through which is fed one of either oxidant or fuel, preferably fuel. Outlet 306 is connected to feed line 302 through which is fed the other of either oxidant or fuel, preferably oxidant. The fuel and oxidant are fed through their respective feed lines from conventional sources thereof, such as storage tanks with suitable valves and controls. Preferred fuels include gaseous hydrocarbons such as natural gas, propane, methane, mixtures thereof, and the like. Preferred oxidants include air, oxygen-enriched air having an oxygen content greater than 21 vol. %, and oxygen streams containing at least 90 vol. % or even at least 98 vol. % oxygen.

Oxidant and fuel are combusted in flame 311 within conduit 100, in direct contact with the stream 602 that is flowing within conduit 100. The effects of the flame are described below. One burner 310 or more than one burner 310 can be located at any point or points between boiler 10 and oil wells 40. Thus, in FIGS. 5, 6 and 8, the steam-containing stream that stream 602 can be includes any of streams 104, 106, 105, 107, 30 or 108.

It should be noted that in the apparatus depicted in FIGS. 5, 6 and 7, there is no enclosure forming a combustion chamber within which the fuel and the oxidant combust before their combustion products contact the steam in the conduit. Instead, as noted herein, the flame directly contacts the steam. The hot combustion products formed by the combustion also directly contact the steam in conduit 100.

It should also be noted that as shown in FIGS. 5, 6 and 7, the fuel and oxidant are fed into the stream of steam in a direction that is the same direction as the flow of steam. The respective flows can be parallel or within an angle of less than 45° to each other. Arranging the flows in this way helps to maintain flame stability. It also lets the steam flow protect the walls of conduit 100 from overheating due to the heat of the flame 311. Instead, the flowing steam is entrained in the hot combustion products which imparts energy to the steam, evaporates droplets of liquid water present in the steam, and permits the temperature of the steam to be increased. Condensed water (condensate) on the inner walls of conduit 100 can be evaporated by radiative and convective heat transfer from the flame. Steam generated from the combustion of the fuel and oxidant increases the amount of steam delivered to the well (compared to what was produced in the steam generator). Other components of the combustion reaction products (particularly CO₂) may be advantageous for oil recovery or at worst, inert.

In operation, the fuel and oxidant are fed to burner 310 and combusted as described above with respect to FIGS. 1-4 or at the respective outlets 304 and 306 as shown in FIG. 5. The flow rates of the fuel and oxidant will depend on the size of the apparatus, the size of the conduit 100, the flow rate of the steam in the stream being heated, and the amount of combustion energy that is needed to achieve the energy level targeted for stream 106. The stoichiometric ratio between the fuel and oxidant should be such that there is no more than 5% excess oxygen. Preferably the stoichiometric ratio should be 1:1 or with a slight excess of fuel.

There are a number of ways to practice the current invention. For example, although the burner could be an air-fuel burner, it is more advantageous to use enriched air or pure oxygen as the oxidant. An air burner would require specific methods (such as swirl, bluff bodies, and others known to experts in the art) to achieve flame stability in the steam environment. In some cases nitrogen contained in the flue gas, and injected into the well, may be undesirable. In contrast using oxygen enriched air, or pure oxygen, would enhance flame stability and reduce the nitrogen content of the resultant mixture of the combustion products with the steam. This is shown in Table 1. For this table the total assumed heat loss is approximately 71% of the latent heat of the steam leaving an OTSG, representing a well far away from the OTSG. As can be seen from Table 1, reheating the steam yields almost a 4 fold increase in oil production. However, if air is used instead of substantially pure oxygen, the injection gas would contain approximately 20 vol. % of nitrogen which could create issues for the desired oil recovery from the well. Gas produced with the oil could contain nitrogen quantities so large that the gas would not be useable as a fuel with nitrogen rejection.

TABLE 1 Comparison of Air-fuel and Oxy-fuel burners for steam reheating at well Reheated Reheated with with Leaving Baseline air-fuel oxy-fuel OTSG at well burner burner Total water flow¹ relative to 1 1.06 1.06 leaving OTSG Steam Quality²  95.0%  27.5% 95.0% 95.0% Gas composition (volume %) CH₄  0.0%  0.0% CO₂  2.5%  2.9% H₂O 100.0% 100.0% 78.7% 97.1% N₂ 18.8%  0.0% Oil production³ relative 1 3.7 3.7 to baseline ¹includes liquid and vapor ²defined as the mass ratio of steam/(steam + liquid) ³assumes 2 bbl steam/bbl oil

Another aspect of the current invention is the location of the burner relative to the well. In some cases, as that shown previously in Table 1, the burner can be located at the well, or potentially even in the wellbore itself (as shown in FIG. 7). In this case an oxidant supply and a fuel supply must be provided for each well. Another option would be to superheat the steam further upstream in the steam distribution system to such that a single burner can reheat/superheat the steam for multiple wells. In this case it will be important to provide at least enough heat to offset transportation heat losses while avoiding temperature limitations. For example, in the extreme case where the burner is located at the OTSG the steam would need to be superheated more than 400° F. to offset the heat loss used for Table 1. Placing the burner downstream, but before the steam is split into the piping for individual wells, would reduce the superheat temperature.

Other alternate modes for the current invention include addition of CO₂ to the steam before heating to promote recoveries in reservoirs where CO₂ can reduce oil viscosity.

Another preferred embodiment is the inclusion of a device to prevent entrained water droplets from directly impinging on the flame (as a method to enhance flame stability). For example, referring again to FIG. 5, one embodiment would be a metal shield 120 (with or without perforations) in the path of stream 602 and extending beyond the outlets 304 and 306 and only partially around the base 317 of flame 311. This embodiment protects the base 317 of flame 311 from impingement by droplets of water, without creating a combustion chamber that would keep the flame from directly contacting the steam.

An alternative embodiment would be a structure such as a cyclone 314, an example of which is shown in FIG. 8 which is a top view of one embodiment of FIG. 5. In the arrangement shown in FIG. 8, the path in which stream 602 flows curves to follow the shape of the inner surface of conduit 100, around the axis of burner 310. However, droplets of liquid water in stream 602 continue in a different path toward the inner surface of conduit 100. This helps to separate condensate and force it toward the conduit walls to keep it away from the burner but still allow the water to be evaporated by the heat of combustion from flame 311. In some cases this practice would impinge water droplets on the conduit wall.

In a preferred mode of operation of the invention, the invention is employed in situations in which the stream of steam flowing from its source toward the oil well(s) loses heat to the surrounding environment before reaching the oil well(s) 40, such as through conduit walls even though they may be insulated. Similarly, stream 105 may lose heat between separator 20 and the oil well(s) 40. Such heat loss reduces the temperature and/or the steam quality of the stream 108 that reaches the oil well(s) 40.

In such situations, the present invention is practiced to alleviate these heat losses, by operating one or more than one system 13 and/or 15 between separator 20 and oil well(s) 40 in a manner, and at a location or locations, so that the heat transfer to the steam as described herein imparts enough energy to the steam such that the temperature or quality of said steam at said oil well(s) is at least equal to its temperature or quality at the source of said steam. In another more preferred mode of operation of the invention, enough energy is imparted to the steam that the temperature or quality of said steam at said oil well(s) is higher than its temperature or quality at the source of said steam. More preferably, the one or more systems 13 and/or 15 are located and are operated such that the steam quality in the stream at the oil well(s) 40 is at least 99%. Even more preferably, the steam in stream 108 at the oil well(s) 40 is saturated or superheated, by the manner in which the system systems 13 and/or 15 are operated and the location where it or they are located. It will be recognized that the location of any such systems 13 and 15, and the manner in which they are operated, are related in that increased distance between the oil well(s) 40 and the closest system 13 or 15 increases the steam quality and the temperature or degree of superheating that are provided in stream 107 from such closest system, in order to provide a given desired steam quality, degree of superheating, and /or temperature at the oil well(s) 40.

The present invention provides numerous advantages.

One advantage is that unit 11 before the separator 20 significantly reduces the relative volume and flowrate of the blowdown stream 207, to values in the range of 2-5% of the total boiler feed water stream, as compared to 20% of the total boiler feed water stream operation without unit 11. In this manner the size and operating cost for the condensate recovery section 70 are significantly reduced.

The present invention compensates for heat losses in the SAGD process, and consequently maintains higher oil production rates, while minimizing at the same time additional incurred costs. There are significant heat losses on the steam path from the facility where the SAGD operation is carried out to the oil reservoir, due to heat losses from the steam pipeline infrastructure or in the injection well. Thus, even if the steam quality of stream 105 leaving the separator 20 is 100%, the steam quality of the stream of steam that reaches the well head, stream 108, may drop to 94-98% or lower, e.g. even to 90% or less. Furthermore, the heat losses in the well bore are significant, so that when the steam actually reaches the reservoir underground it may have a steam quality in the range of 80-90%. Basically, the heat losses encountered from the pipelines and in the well bore result in lower energy transferred to the reservoir, and therefore a decrease in oil production.

The present invention, by making up for heat losses from the pipeline, can result in an increase in oil production of up to 20%, using steam generation from the existing boiler, compared to production using steam generation from the existing boiler without the heat transfer described herein.

The current invention can also be used to superheat the steam to allow more thermal energy to be carried to the well. In a conventional OTSG steam quality (which is defined in Table 1) is intentionally kept below 1 (not full evaporation) due to poor boiler feedwater quality. If all the water is evaporated in the OTSG the water contaminants will condense/plate out on the inside of the conduits—reducing the heat transfer efficiency of the conduits and potentially leading to conduit failures. However in the current invention the heat transfer to the steam/liquid is by direct contact with the flame and combustion products, therefore any precipitation of feedwater contaminants on the wall will not impact the boiling/superheating efficiency. As long as the conduit 100 is sized to avoid flow disruptions caused by the reduction of the conduit's internal diameter by deposition of feedwater contaminants over the anticipated life of the conduit, superheating with the current invention is feasible and in some cases attractive. Another consideration is the maximum working temperature of the steam piping, which limits the amount of superheating that can be provided. 

What is claimed is:
 1. A method of providing steam suitable for injection into a subterranean oil well, comprising combusting fuel with gaseous oxidant and subjecting a stream that comprises steam flowing from a source of said steam to a subterranean oil well to direct heat transfer to said stream of heat produced by said combustion, thereby increasing the steam quality of said stream to a value that is above 80% and that is higher than the steam quality of the stream produced by said source.
 2. A method according to claim 1 wherein the stream which is subjected to said direct heat transfer contains liquid water, and the method further comprises separating liquid water from the stream which has been subjected to said direct heat transfer, thereby providing a product stream comprising steam.
 3. A method according to claim 1 wherein said gaseous oxidant is air.
 4. A method according to claim 1 wherein said gaseous oxidant comprises at least 25 vol. % oxygen.
 5. A method according to claim 1 wherein said gaseous oxidant comprises at least 90 vol. % oxygen.
 6. A method according to claim 2 further comprising further heating the product stream.
 7. A method according to claim 2 further comprising further heating the product stream by direct heat transfer or indirect heat transfer with heat of combustion produced by further combustion of fuel and gaseous oxidant.
 8. A method according to claim 7 wherein said gaseous oxidant combusted in said further combustion is air.
 9. A method according to claim 7 wherein said gaseous oxidant combusted in said further combustion comprises at least 25 vol. % oxygen.
 10. A method according to claim 7 wherein said gaseous oxidant combusted in said further combustion comprises at least 90 vol. % oxygen.
 11. A method according to claim 6 wherein said stream of steam flowing from said source to said oil well loses heat to the environment, and wherein said further heating of said product stream imparts enough energy to said product stream such that the temperature of said product stream at said oil well is at least equal to the temperature of the stream produced by said source or the steam quality of said product stream at said oil well is at least equal to the steam quality of the stream produced by said source.
 12. A method according to claim 11 wherein said further heating of said product stream imparts enough energy to said product stream that the temperature of said product stream at said oil well is higher than the temperature of the stream produced by said source or the steam quality of said product stream at said oil well is higher than the steam quality of the stream produced by said source.
 13. A method according to claim 6 wherein said stream of steam flowing from said source to said oil well loses heat to the environment, and wherein said further heating of said product stream imparts enough energy to said product stream such that the steam quality of said product stream at said oil well is at least 99%.
 14. A method according to claim 6 wherein said stream of steam flowing from said source to said oil well loses heat to the environment, and wherein said further heating of said product stream imparts enough energy to said product stream such that said product stream at said oil well is saturated steam.
 15. A method according to claim 6 wherein said stream of steam flowing from said source to said oil well loses heat to the environment, and wherein said further heating of said product stream imparts enough energy to said product stream such that said product stream at said oil well is superheated.
 16. A method according to claim 1 wherein said direct heat transfer causes the steam quality of the product stream at said oil well to be at least 98%.
 17. A method of providing steam suitable for injection into a subterranean oil well, comprising feeding fuel and gaseous oxidant into a stream that comprises steam flowing in a conduit from a source of said steam to a subterranean oil well, wherein said fuel and said oxidant are fed into said stream from one or more outlets located in said stream within said conduit, and combusting said fuel with said oxidant at one or more of said outlets in direct contact with said steam, and heating said steam by direct contact of said steam with hot combustion products produced by said combustion.
 18. A method according to claim 17 wherein said stream of steam into which said fuel and oxidant are fed contains liquid water, and wherein said heating of said steam evaporates at least a portion of said liquid water.
 19. A method according to claim 17 wherein said stream of steam flowing in said conduit loses heat to the environment outside said conduit, and wherein said direct contact of said steam with said hot combustion products imparts enough energy to said steam such that the temperature or quality of said steam at said oil well is at least equal to its temperature or quality at the source of said steam.
 20. A method according to claim 17 wherein said stream of steam from said source contains liquid water, the method further comprising physically reducing the amount of liquid water in said stream that contacts the base of the flame that is formed by combusting said fuel and said oxidant.
 21. A method according to claim 20 wherein said reducing the amount of liquid water comprises passing said stream toward a deflector disposed between the path of said stream and said base of said flame, the deflector only partially surrounding said base, wherein liquid water contacts said deflector instead of contacting said base of said flame.
 22. A method according to claim 20 wherein said reducing the amount of liquid water comprises, before said stream contacts said base of said flame, flowing said stream through a path that causes liquid water in said stream to move toward an inner surface of said conduit and in a path that differs from the path of said stream.
 23. A method of providing steam suitable for injection into a subterranean oil well, comprising feeding fuel and gaseous oxidant into a stream that comprises steam flowing in a conduit from a source of said steam in a subterranean oil well, wherein said fuel and said oxidant are fed into said stream from one or more outlets located in said stream within said conduit, and combusting said fuel with said oxidant at one or more of said outlets in direct contact with said steam, and heating said steam by direct contact of said steam with hot combustion products produced by said combustion. 